Logging tool with independently energizable transmitters

ABSTRACT

A downhole induction resistivity assembly that comprises a downhole tool string component. The tool string component comprises an induction transmitter. The transmitter is adapted to induce an induction field in the surrounding formation. A first induction receiver is spaced apart from the transmitter and is adapted to measure the induction field. A magnetic field generating mechanism is disposed adjacent on either or both sides of the transmitter and adapted to guide the transmitter&#39;s signal into the formation. A second induction receiver is disposed in close proximity to the magnetic field generating mechanism and is adapted to measure the magnetic field generated by the mechanism.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.12/341,872 filed on Dec. 22, 2008 now U.S. Pat. No. 7,888,940 andentitled “Induction Resistivity Cover”, which is a continuation of U.S.patent application Ser. No. 12/341,771 filed on Dec. 22, 2008 now U.S.Pat. No. 7,898,259 and entitled “Resistivity Reference Receiver”, whichis a continuation-in-part of U.S. patent application ser. No. 11/776,447filed on Jul. 11, 2007 and entitled “Externally Guided and DirectedField Induction Resistivity Tool”, that issued Oct. 6, 2009 as U.S. Pat.No. 7,598,742, which, in turn, claims the benefit of U.S. ProvisionalPatent Application No. 60/914,619 filed on Apr. 27, 2007 and entitled“Resistivity Tool”.

U.S. patent application Ser. No. 12/341,771 is also a continuationin-part of U.S. patent application Ser. No. 11/687,891 filed on Mar. 19,2007 and entitled “Multiple frequency Inductive Resistivity Device”,that issued on Nov. 27, 2007 as U.S. Pat. No. 7,301,429. U.S. patentapplication Ser. No. 12/341,771 is also a continuation-in-part of U.S.Patent application Ser. No. 11/676,494, filed on Feb. 19, 2007 andentitled “Flexible Inductive Resistivity Device”, that issued Sep. 4,2007 as U.S. Pat. No. 7,265,649. U.S. patent application Ser. No.12/341,771 also claims the benefit of U.S. Provisional patentApplication No. 61/073,190 filed on Jun. 17, 2008 and entitled “DownholeCover”. All of the above mentioned references are herein incorporated byreference for all that they contain.

BACKGROUND OF THE INVENTION

Electric resistivity of a downhole formation is often measured from awireline or drill string component in a well bore to analyze formationparameters. Induction resistivity tools induce a magnetic field into theformation; and thus, are different from laterolog resistivity systems,where an electric current is passed through the formation.

U.S. Pat. No. 6,677,756 to Fanini et al., which is herein incorporatedby reference for all that it contains, discloses an induction tool forformation resistivity evaluations. The tool provides electromagnetictransmitters and sensors suitable for transmitting and receivingmagnetic fields in radial directions.

U.S. Pat. No. 6,359,438 to Bittar, which is herein incorporated byreference for all that it contains, discloses a resistivity tool for usein an LWD system that includes a transmitter array with multipletransmitters positioned above a pair of receivers. The transmitters areselectively energized, causing current to be induced in the collar ofthe tool.

U.S. Pat. No. 6,577,129 to Thompson et al., which is herein incorporatedby reference for all that it contains, discloses an electromagnetic wavepropagation resistivity borehole logging system comprising multiplegroups of electromagnetic transmitter-receiver arrays operating at threefrequencies.

U.S. Pat. No. 6,538,447 to Bittar, which is herein incorporated byreference for all that it contains, discloses a multi-mode resistivitytool for use in a logging while-drilling system that includes anasymmetric transmitter design with multiple transmitters capable ofgenerating electromagnetic signals at multiple depths of investigation.

U.S. Pat. No. 7,141,981 to Folbert et al., which is herein incorporatedby reference for all that it contains, discloses a resistivity loggingtool suitable for downhole use that includes a transmitter, and twospaced apart receivers. The measured resistivities at the two receiversare corrected based on measuring the responses of the receivers to acalibration signal.

U.S. Pat. No. 6,218,842 to Bittar et al., which is herein incorporatedby reference for all that it contains, discloses a resistivity tool foruse in LWD systems that includes an asymmetric transmitter design withmultiple transmitters capable of generating EM signals at multiplefrequencies.

U.S. Pat. No. 5,045,795 to Gianzero et al., which is herein incorporatedby reference for all that it contains, discloses a coil array which isinstalled on a MWD drill collar for use in a resistivity logging system.The drill collar is provided with upper and lower coil support rings.These are toroids which support individual coil segments, and areconnected by suitable magnetic shorting bars. The coil segments andshorting bars inscribe a specified solid angle or azimuthal extent.

U.S. Pat. No. 5,606,260 to Giordano et al., which is herein incorporatedby reference for all that it contains, discloses a microdevice isprovided for measuring the electromagnetic characteristics of a mediumin a borehole. The microdevice includes at least one emitting ortransmitting coil (31), and at least one receiving coil (41,51). Themicrodevice generates an A.C. voltage at the terminals of thetransmitting coil and measures a signal at the terminals of thereceiving coil. The microdevice also includes an E-shaped electricallyinsulating, soft magnetic material circuit serving as a support for eachof the coils and which is positioned adjacent to the medium in theborehole.

U.S. Pat. No. 6,100,696 to Sinclair, which is herein incorporated byreference for all that it contains, discloses a directional inductionlogging tool is provided for measurement while drilling. This tool ispreferably placed in a side pocket of a drill collar, and it comprisestransmitter and receiver coils and an electromagnetic reflector.

U.S. Pat. No. 6,163,155 to Bittar et al., which is herein incorporatedby reference for all that it contains, discloses a downhole method andapparatus for simultaneously determining the horizontal resistivity,vertical resistivity, and relative dip angle for anisotropic earthformations.

U.S. Pat. No. 6,476,609 to Bittar et al., which is herein incorporatedby reference for all that it contains, discloses an antennaconfiguration in which a transmitter antenna and a receiver antenna areoriented in nonparallel planes such that the vertical resistivity andthe relative dip angle are decoupled.

SUMMARY OF THE INVENTION

A downhole induction resistivity assembly comprises a downhole toolstring component. The tool string component comprises an inductiontransmitter. The transmitter is adapted to induce an induction field inthe surrounding formation. A first induction receiver is spaced apartfrom the transmitter and is adapted to measure the induction field. Amagnetic field generating mechanism is disposed adjacent on either orboth sides of the transmitter and adapted to guide the transmitter'ssignal into the formation. A second induction receiver is disposed inclose proximity to the magnetic field generating mechanism and isadapted to measure the magnetic field generated by the mechanism.

The magnetic field generating mechanism generates an augmented magneticfield. The mechanism generates a directed magnetic field. Someembodiments of either the magnetic field generating mechanism or theinduction transmitter may comprise: a Halbach array, a substantiallyU-shaped magnetic core, at least one coil disposed circumferentiallyabout the tool (wherein a magnetically conductive, electricallyinsulating material is disposed adjacent a surface of the component andthe coil), or some other magnetic field inducing mechanism.

The transmitter and/or at least one of the receivers may comprise amagnetic core disposed substantially parallel with an axis of the toolstring component. The transmitter and/or at least one of the receiversmay also comprise a plurality of circumferentially spaced units that areindependently excitable. The units may also be tilted with respect tothe central axis. The input and/or outputs from the units may bemultiplexed.

One of the receivers may comprise a core that is positionedsubstantially perpendicular to another induction resistivity receiver.The transmitter may be adapted to generate the induction field at adifferent phase, frequency, and/or amplitude than the mechanism isadapted to generate the magnetic field. The resistivity assembly maycomprise a control-loop adapted to execute a command to the mechanism toadjust a characteristic of the magnetic field, such characteristicsbeing selected from the group consisting of phases, amplitudes,frequencies, strength, or combinations thereof. The transceiver and/orat least one of the receivers may comprise litz wire.

BRIEF DESCRIPTION OF THE DRAWINGS

To further clarify the above and other advantages and features of theone or more present inventions, reference to specific embodimentsthereof are illustrated in the appended drawings. The drawings depictonly typical embodiments and are therefore not to be consideredlimiting. One or more embodiments will be described and explained withadditional specificity and detail through the use of the accompanyingdrawings in which:

FIG. 1 is a cross-sectional diagram of an embodiment of a downhole toolstring.

FIG. 2 is a perspective diagram of an embodiment of tool stringcomponent.

FIG. 3 a is a perspective diagram of an embodiment of an inductiontransmitter.

FIG. 3 b is a perspective diagram of an embodiment of an inductionreceiver.

FIG. 4 a is a perspective diagram of an embodiment of an inductionresistivity assembly disposed downhole.

FIG. 4 b is a perspective diagram of another embodiment of an inductionresistivity assembly disposed downhole.

FIG. 5 a is a perspective diagram of another embodiment of an inductionreceiver.

FIG. 5 b is perspective diagram of another embodiment of an inductiontransmitter.

FIG. 5 c is a perspective diagram of another embodiment of an inductionreceiver.

FIG. 5 d is a perspective diagram of another embodiment of an inductiontransmitter.

FIG. 6 a is a perspective diagram of another embodiment of an inductiontransmitter.

FIG. 6 b is a perspective diagram of another embodiment of an inductionreceiver.

FIG. 7 a is a perspective diagram of another embodiment of an inductiontransmitter.

FIG. 7 b is a perspective diagram of another embodiment of an inductiontransmitter.

FIG. 8 a is a perspective diagram of another embodiment of an inductiontransmitter.

FIG. 8 b is a diagram of an embodiment of electronic assemblies disposedwithin a downhole component.

FIG. 9 is a perspective diagram of a downhole tool string component.

FIG. 10 a is a cross sectional diagram of a downhole tool stringcomponent.

FIG. 10 b is a cross sectional diagram of a downhole tool stringcomponent.

FIG. 10 c is a cross sectional diagram of a downhole tool stringcomponent.

FIG. 10 d is a cross sectional diagram of a downhole tool stringcomponent.

FIG. 11 a is a perspective diagram of a downhole tool string component.

FIG. 11 b is a perspective diagram of a downhole tool string component.

FIG. 12 a is a perspective diagram of a downhole tool string component.

FIG. 12 b is a plot of an embodiment of data gathered from a downholetool string component.

FIG. 13 is a perspective diagram of a downhole tool string component.

FIG. 14 a is a cross sectional diagram of a downhole tool stringcomponent.

FIG. 14 b is a cross sectional diagram of a downhole tool stringcomponent.

DETAILED DESCRIPTION

Referring now to FIG. 1, a downhole tool string 101 may be suspended bya derrick 102. The tool string may comprise one or more downholecomponents 100, linked together in a tool string 101 and incommunication with surface equipment 103 through a downhole network.Networks in the tool string 101 may enable high-speed communicationbetween devices connected to the tool string, and the networks mayfacilitate the transmission of data between sensors and sources. Thedata gathered by the downhole components 100 may be processed downhole,may be transmitted to the surface for processing, may be filtereddownhole and then transmitted to the surface for processing or may becompressed downhole and then transmitted to the surface for processing.

FIG. 2 is an embodiment of a tool string component 100. The tool stringcomponent may comprise an induction transmitter 201 and a plurality ofinduction receivers 203 a-e. The receivers 203 a-e may be placed in avariety of orientations with respect to each other and to thetransmitter 201. The induction transmitter 201 is adapted to send aninduction signal in to the formation, which generates a formationinduction field surrounding the well bore. The induction receivers 203a-e are adapted to sense various attributes of the induction field inthe formation These attributes may include among others, some or all ofthe following: frequency, amplitude, or phase. The transmitter and thereceivers may be powered by batteries, a turbine generator or from thedownhole network. The receivers may also be passive. In someembodiments, there may be several induction transmitters located alongthe length of the tool string component. In some embodiments, theadditional transmitters may be used to calibrate measurements, such asin common in borehole compensation techniques.

The transmitter 201 and receivers 203 a-e may communicate with thenetwork through a multiplexer 310. The reference receiver 202 andreceivers 203 a-e may be spaced along a central axis 1000 of thecomponent 100 from the transmitter such that: a first reference receiver202 is spaced a distance 204 that is 10 to 14 inches from the center ofthe transmitter 201, a first receiver 203 a is spaced a distance 205that is 16 to 20 inches from the center of the transmitter 201, a secondreceiver 203 b is spaced a distance 206 that is 23 to 28 inches from thecenter of the transmitter 201, a third receiver 203 c is spaced adistance 207 that is 38 to 43 inches from the center of the transmitter201, a fourth receiver 203 d is spaced a distance 208 that is 52 to 57inches from the center of the transmitter, a fifth receiver is spaced 52to 57 inches 208 from the center of the transmitter 201, and a fifthreceiver 203 e is spaced a distance 209 that is 77 to 82 inches from thecenter of the transmitter 201.

FIG. 3 a is a perspective view of an embodiment of a transmitter 201disposed within a drill string component and FIG. 3 b is a perspectiveview of an embodiment of three receivers 202, 203, and 304. Thetransmitter 201 may comprise an array of transmitter units 301 spacedcircumferentially around the tool string 100. The transmitter units 301may lie parallel to the body of the drill string. The transmitter units301 may be independently excitable. Independently excitable units mayfocus the induction field in only a portion of the formation adjacent tothe excitable units while the remaining portion of the formation isminimally affected or not affected at all. Furthermore it is believedthat the ability to concentrate the field in portions of the formationadjacent the well bore will allow for directional measurements of theformation. Data received through directional measurement may verify acurrent drilling trajectory or it may reveal needed adjustments.Steering adjustments may be made by a steering system in communicationwith a downhole communication system, such as the system disclosed inU.S. Pat. No. 6,670,880, which is herein incorporated by reference forall that it discloses. An embodiment of a compatible steering system isdisclosed in U.S. patent application Ser. No. 12/262,372 to Hall et al.,which is herein incorporated by reference for all that it contains.

The transmitter 201 may also comprise a magnetic field generatingmechanism 302, which may guide the induction field produced by thetransmitter units 301 by forcing the transmitter's signal deeper intothe formation. The windings on the transmitter 201 may be in a differentdirection then the windings on the magnetic field generating mechanism302. In some embodiments, the magnetic field generating mechanism 302may generate an augmented field or a directed field. Examples ofmagnetic field generating mechanism that may be used to influence thesignal from the transmitter include Hallbach arrays, electric magnets,and directed magnetic field. Without the magnetic field generatingmechanism 302 the transmitter's signal may travel along the path of lestresistance which could be within a shallower region of the formation oreven along the surface of the tool string component. The magnetic fieldgenerating mechanism 302 may generate a magnetic field that will repelthe signal away from the tool string component, and thus, deeper intothe formation. The magnetic field generating mechanism 302 may have astartup sequence such that when the transmitter 201 first starts areference receiver 202 measures the field strength and through a controlloop adjusts the output of the magnetic field generating mechanism 302until the field measured by the reference receiver 202 is at a desiredstrength. The magnetic field generating mechanisms 302 may also haveunits that are independently excitable with respect to phase, frequency,or magnitude.

The reference receiver 202 may be disposed in the tool string componentin close proximity to the magnetic field generating mechanism 302. Thereference receiver 202 is close enough to the magnetic field generatingmechanism 302 that it is excitable by the magnetic field generatingmechanism 302, not just the induction field that is regenerated in theformation. The other receivers 203 may be less sensitive to theinduction field generated by the magnetic field generating mechanism302. Thus, the reference receiver 202 may determine the strength,magnitude, phase, and other parameters of the signal generated by themagnetic field generating mechanism 302. If the magnetic fieldgenerating mechanism 302 produces a magnetic field that is too weak themagnetic field may be ineffective, and if the magnetic field is toostrong it may inhibit the transmitter's 201 induction field frompenetrating the formation at all. Such parameters may be used to adjustthe magnetic field generating mechanism 302 to produce an optimal signalfor the desired penetration of the induction field into the formation.The resistivity tool may comprise a control loop that is adapted toexecute a command to adjust at least one parameter of the magnetic fieldgenerating mechanism 302; the characteristics may be selected from thegroup consisting of phases, amplitudes, frequencies, strength, orcombinations thereof. In some embodiments the telemetry system mayinclude mud pulse, EM, short-hop, and/or wired pipe, the command toadjust the signal may be from surface equipment or generated downhole.In some embodiments, the signal is executed automatically or it may beexecuted manually.

In some embodiments, the reference receiver 202 may be capable ofsensing both the magnetic field and the induction field. In such cases,the signals from the transmitter 201 and the magnetic field generatingmechanism 302 may comprise different parameters such as differentfrequencies, different phases, different amplitude, and/or signalstrength so that the signals may be distinguishable. In some embodiment,the other receivers 203 may also be close enough to sense the magneticfield.

The reference receiver 202 may be comprised of an array of referencereceiver units 303. The reference receiver units 303 may liesubstantially parallel to a longitudinal axis of the body of the toolstring component. The reference receiver 202 may comprise a spoolreceiver 304 that may comprise a magnetically conductive core that isdisposed perpendicular to the body of the drill string and anotherinduction resistivity receiver. The spool receiver 304 may be part of areference receiver assembly. Since the core of the spool receiver 304and the reference receiver units 303 lie on different planes they senseboundaries of the subterranean formation that the other cannot. In someembodiments, the reference receiver units 303 and the core of the spoolreceiver 304 are oriented such that they are not substantiallyperpendicular to each other, but are still adapted to sense boundarybetween subterranean strata at different angles.

Referring now to FIG. 4 a, an embodiment of a tool string component isdepicted in a borehole 405. The drill string component 100 comprises atransmitter 201, a reference receiver 202, and receivers 203. Thetransmitter 201 is depicted generating an induction signal 401 with themagnetic field generating mechanism 302 being inactive. Drilling mud 402is disposed between the tool string component and the formation 403. Themagnetic field 401 may tend to predominately travel within the borehole405 or within a shallow portion of the formation infiltrated by drillingmud and may not penetrate deeply into the formation 403. This mayprevent an actual depiction of the formation surrounding the bore hole.FIG. 4 b depicts an embodiment of a tool string component with both thetransmitter unit 301 and the magnetic field generating mechanism 302activated, which shows the induction signal traveling deeper in theformation It is believed that by adjusting the output of the magneticfield generating mechanism 302 the penetration depth of the inductionsignal 401 may be adjusted. The magnetic field generating mechanisms 302may be positioned on both sides of the transmitter 201.

FIG. 5 a discloses an embodiment of a spool receiver 304. The spoolreceiver 304 may comprise a ferrite core 506 wrapped in wire 504. FIG. 5b discloses an embodiment of a magnetic field generating mechanism 302.The magnetic field generating mechanism 302 may comprise a U-shapedferrite core 507 wrapped in wire 509. FIG. 5 c discloses an embodimentan independently excitable unit of a receiver unit 305 and/ortransmitter with a ferrite core 502 wrapped in wire 505. FIG. 5 ddiscloses an embodiment of a transmitter unit 301 and/or receiver. Thetransmitter unit 301 may comprise a ferrite core 500 wrapped in wire501. In some embodiments, the wire 501, 505, 509 depicted in FIGS. 5 a-dmay be Litz wire. In some embodiments, the wire windings on the variouscomponents may be wrapped in different directions or different patternsthen each other.

FIG. 6 a depicts an embodiment of a portion of a tool string component100. In this embodiment the transmitter units 301 and the magnetic fieldgenerating mechanisms 302 are tilted with respect to a central axis ofthe tool string 100. In FIG. 6 b an embodiment of a portion of a toolstring component 100 discloses the reference receiver units 303 and thereceiver units 305 tilted with respect to a central axis of a toolstring component. The tilt angle may be at any degree. In someembodiments, the tilt angle is between 10 and 50 degrees with respect tothe central axis.

FIG. 7 a is an embodiment of a transmitter 201 disposed on a tool stringcomponent 100. In this embodiment the transmitter units 701 comprises aHalbach array. FIG. 7 b is an embodiment of a transmitter 201 disposedon a tool string component 100. In this embodiment the magnetic fieldgenerating mechanism 702 comprises a Halbach array. It is believed thatthe Halbach array will direct a greater magnitude of the magnetic fieldfor a given power into the formation then a standard transmitter.

FIG. 8 a depicts an embodiment of a transmitter 201 where thetransmitter comprises wire windings 803 wound circumferentially aroundthe tool string component 100. The wire is disposed within a trough ofmagnetically conductive, electrically insulating (MCEI) material 1800that is disposed adjacent a surface of the component and the coil. TheMCEI material may comprise mu-metals, ferrite, and/or iron. Anembodiment of a transmitter that may be compatible with the presentinvention is disclosed in U.S. patent application Ser. No. 11/676,494,which is herein incorporated by reference for all that it discloses.

FIG. 8 b discloses an embodiment of a portion of a tool string component100. The tool string 100 may comprise a multiplexer 801. The multiplexermay be adapted to take data from multiple inputs and put all of the dataonto a lesser number of outputs. The tool string component may alsocomprise a processing element 802. The processing element 802 may beadapted to process data and send out commands to the tool string 100.That data may comprise among other data any or all of the following:data from the receivers, data from the reference receiver, or data fromthe transmitter. The processing element 802 may send commands to asteering assembly to guide the tool string 100 in a desired direction.

FIG. 9 is a perspective diagram of a downhole tool string component 100in operation downhole. The tool string component 100 is connected to adrill bit 900 comprising a steering mechanism 901 protruding beyond thefront face of the bit. Also shown are a plurality of receivers 203disposed along the tool string component and the drill bit. Thereceivers may be positioned on different downhole components or they maybe positioned along a single downhole component. The farthest mostreceiver 902 from the transmitter may be disposed on the drill bit andpositioned between the wrench flats 903 of the drill bit and the drillbit's cutting blades 904. The resistivity tool may be used forgeo-steering applications where it is desirable to stay within aspecific formation layer. The resistivity tool may help identify theformation type boundaries. In embodiments where the resistivity tool isconnected to a feed back loop, a command may be sent from a processingelement associated with the resistivity tool to a steering system toadjust the tool string's trajectory to keep the tool string within thepreferred layer. In some embodiments, data from the resistivity tool maybe received up-hole through a telemetry system and adjustments to thesteering may be executed remotely. Data may be gathered from any of thesensors while the drill bit is rotating, while the drill bit is sliding,or while the drill bit is stationary. A rotary steerable system that maybe compatible with the present invention is disclosed in U.S. Pat. No.7,360,610, which is herein incorporated by reference for all that itdiscloses.

FIGS. 10 a, 10 b, 10 c, and 10 d are cross sectional views of a downholecomponent depicting the individually excitable induction units 301. Insome embodiments, these units 301 may be excited at once, in pairs, ingroups, or individually. In some applications it may be desirable toanalyze only a portion of the borehole wall. In some applications, whereaccuracy is critical, the drill string may be stopped, and the units maybe individually activated. In other embodiments, a single unit may beactivated while the drill string rotates, and thus, induces an inductionfield around the entire circumference of the bore hole. The transmitterunits 301 may be activated in a number of different orders. Theactivation orders may include but are not limited to the orders depictedin FIGS. 10 a, 10 b, 10 c, and 10 d. The transmitter segments 301 may beactivated in a clockwise or counter clockwise direction.

FIG. 11 a depicts an embodiment of an irradiated plastic cover 1210disposed around a tool string component 100. It is believed that theirradiated plastic cover 1210 may protect the transmitters andreceivers. It is also believed the cover 1210 will minimally interferewith the induction waves. The cover 1210 may comprise a materialselected from a group of thermoplastic polymers. The cover may comprisea polyetheretherketone (PEEK) material. In some embodiments, the plasticmay comprise glass filled PEEK, glass filled Torlon.RTM., Torlon.RTM.,polyamide-imide, glass filled polyamide-imide, thermoplastic,polyimides, polyamides or combinations thereof. The cover material mayhave a melting point between 333.9 degrees Celsius and 350 degreesCelsius. The cover material may have a tensile strength of between 70megapascals and 100 megapascals. The cover may take the form of a sleevedisposed around the tool string component. As shown in FIG. 11 b, thecover may also comprise irradiated plastic windows 1202 configured tocover the individual transmitter units 1201 or receiver units 1203,1205.

FIG. 11 b depicts an embodiment of a data gathering technique. In thistechnique a single transmitter unit 1201 is activated and the generatedsignal 1125 is gathered by an individual receiver unit 1203. Thereceiver unit 1203 that is used to gather the signal 1125 may be at thesame azimuth as the activated transmitter unit 1201. The non-datagathering receiver segments may be deactivated or ignored. This processis repeated with a different set of receivers and transmitters. In someapplications, a portion or all of the transmitters and receivers may beused. Data received at a receiver unit 1205 on a different azimuth thanthat of the transmitter unit 1201 may provide angular data that maycorrespond to a dip angle 1150 (see FIG. 12 b) of a formation.

In FIG. 12 a, the transmitter unit 1100 generates signal 1110 which isreceived by receiver unit 1105, then transmitter unit 1101 generatessignal 1111 which is received by receiver unit 1106, then transmittersegment 1102 generates signal 1112 which is received by receiver unit1107, and finally transmitter unit 1103 generates signal 1113 which isreceived by receiver unit 1108. An embodiment of the gathered data isplotted in FIG. 12 b. The plots may correspond to the gathered data suchthat plot 1123 corresponds to signal 1110, plot 1122 corresponds tosignal 1111, plot 1121 corresponds to signal 1112, and plot 1120corresponds to signal 1113. The plots may be versus either time orfrequency. It is believed that the plots will have an offset 1160 withrespect to each other. It is believed that the offset 1160 of eachconsecutive recorded signal 1125 may be extrapolated to form a line 1152of a certain slope. It is further believed that this line 1152 will forman angle 1151 that is mathematically related to the dip angle 1150 ofthe formation. In FIG. 12 b, only a portion of the extrapolated line isshown, which if fully represented would appear as a sine wave than astraight line.

FIG. 13 depicts another embodiment of a data gathering technique. Inthis technique a transmitter unit 301 is activated and a first receiver203 a and a second receiver 203 b capture the data. The data receivedfrom the first receiver 203 a contains information that corresponds tothe formation 1301 that is adjacent to the tool string component 100between the transmitter 201 and the first receiver 203 a. The datareceived from the second receiver 203 b contains information thatcorresponds to the formation 1302 that is adjacent to the tool stringcomponent 100 between the transmitter 201 and the second receiver 203 b.This data gathering technique utilizes mathematical operations toextract the information that corresponds to the formation 1305 lyingpredominately adjacent to the tool string 100 between the first receiver203 a and the second receiver 203 b.

FIGS. 14 a and 14 b depict different embodiments of receiver units 305.For example, the receiver units 1403 and 1404 may be independentlyexcitable. The receiver units 1403 and 1404 may be electronicallydeactivatable. The receiver units 1403 and 1404 may also be tunable suchthat a virtual receiver unit 1401 is created. A virtual receiver unit1401 may be created when two adjacent receiver units 1403 and 1404adjust their power such that a virtual receiver 1401 can be modeled asbe positioned between the two receiver units 1403 and 1404. FIG. 14 adepicts an embodiment of a virtual receiver unit 1401 that is the resultof the data received by two adjacent receivers units 1403 and 1404 beingequally weighted. FIG. 14 b depicts an embodiment of a virtual receiverunit 1402 that is the result of the data received by receiver unit 1403being weighed more heavily then the data received by receiver unit 1404.The virtual receiver unit 1402 in this case appears closer to receiverunit 1403 than in FIG. 14 a.

Whereas the present invention has been described in particular relationto the drawings attached hereto, it should be understood that other andfurther modifications apart from those shown or suggested herein, may bemade within the scope and spirit of the present invention.

1. A logging tool comprising: a component configured to be conveyed intoa wellbore, said component having a central axis and a length along saidcentral axis, said component including: at least one transmitter adaptedto generate an induction signal and transmit said induction signal intoa formation adjacent to said wellbore, said transmitter including aplurality of transmitter units adapted to be independently energized; aHalbach array proximate said transmitter, said Halbach array beingadapted to generate a magnetic field which influences said inductionsignal; at least one receiver spaced apart from said transmitter alongsaid length of said component, said receiver being adapted to receive areturn induction signal representative of said formation; and, a coverpositioned over at least one of said transmitter and said receiver. 2.The logging tool of claim 1, wherein said plurality of transmitter unitsare disposed in at least one recess of said component.
 3. The loggingtool of claim 1, wherein said plurality of transmitter units are spacedaround said component at a first radial distance.
 4. The logging tool ofclaim 3, wherein said at least one receiver includes a plurality ofreceiver units spaced around the component at a second radial distance.5. The logging tool of claim 4, wherein said receiver units areconfigured for independent deactivation.
 6. The logging tool of claim 4,wherein the first radial distance and the second radial distance areequal.
 7. The logging tool of claim 4, wherein said transmitter unitsand said receiver units are tilted with respect to said central axis ofsaid component.
 8. The logging tool of claim 4, wherein said transmitterunits and said receiver units are substantially parallel with respect tosaid central axis of said component.
 9. The logging tool of claim 1,wherein said cover is a plastic.
 10. The logging tool of claim 1,wherein said component is configured to conveyed into said wellbore onat least one of a drill string and a wireline.
 11. The logging tool ofclaim 1, further comprising: a reference receiver located along saidlength of said component and between said transmitter and said receiver,said reference receiver being adapted to measure said magnetic field andto generate a magnetic field signal representative of said magneticfield; and a control loop adapted to receive said magnetic field signalfrom said reference receiver and to execute a command to said Halbacharray to adjust said magnetic field.
 12. The logging tool of claim 1,wherein at least one of said plurality of transmitter units is adaptedto generate and transmit said induction signal into a portion of saidformation in substantially a single direction.
 13. The logging tool ofclaim 1, wherein at least one of said plurality of transmitter units isadapted to generate and transmit said induction signal into a portion ofsaid formation associated with a fraction of a circumference of saidwellbore.
 14. A logging tool comprising: a component configured to beconveyed into a wellbore, said component having a central axis and alength along said central axis, said component including: at least onetransmitter adapted to generate an induction signal and transmit saidinduction signal into a formation adjacent to said wellbore, saidtransmitter including a plurality of transmitter units adapted to beindependently energized; a magnetic field generating mechanism proximatesaid transmitter, said magnetic field generating mechanism being adaptedto generate a magnetic field which influences said induction signal; atleast one receiver spaced apart from said transmitter along said lengthof said component, said receiver being adapted to receive a returninduction signal representative of said formation; a reference receiverlocated along said length of said component and between said transmitterand said receiver, said reference receiver being adapted to measure saidmagnetic field and to generate a magnetic field signal representative ofsaid magnetic field; a control loop adapted to receive said magneticfield signal from said reference receiver and to execute a command tosaid magnetic field generating mechanism to adjust said magnetic field;and a cover positioned over at least one of said transmitter and saidreceiver.
 15. The logging tool of claim 10, wherein said magnetic fieldgenerating mechanism includes a Halbach array.
 16. The logging tool ofclaim 10, wherein at least one of said plurality of transmitter units isadapted to generate and transmit said induction signal into a portion ofsaid formation in substantially a single direction.
 17. The logging toolof claim 10, wherein at least one of said plurality of transmitter unitsis adapted to generate and transmit said induction signal into a portionof said formation associated with a fraction of a circumference of saidwellbore.
 18. A logging tool comprising: a component configured to beconveyed into a wellbore, said component having with a central axis anda length along said central axis, said component including: at least onetransmitter adapted to generate an induction signal and transmit saidinduction signal into a formation adjacent to said wellbore, saidtransmitter including a plurality of transmitter units adapted to beindependently energized; a magnetic field generating mechanism proximatesaid transmitter, said magnetic field generating mechanism being adaptedto generate a magnetic field which influences said induction signal; atleast one of said transmitter and said magnetic field generatingmechanism including a Halbach array; at least one receiver spaced apartfrom said transmitter along said length of said component, said receiverbeing adapted to receive a return induction signal representative ofsaid formation; and a cover positioned over at least one of saidtransmitter and said receiver.